1. Field of the Invention
This invention relates to a process utilizing a well or wells and includes the steps of testing or measuring formation fluids. More specifically, this invention relates to a method for determining the fractional flow and corresponding saturation of fluid phases in a subterranean reservoir being flooded by a fluid.
2. Description of the Prior Art
A typical oil productive formation is a stratum of rock containing tiny, interconnected pore spaces which are saturated with oil, water, and gas. Knowledge of the relative amounts of these fluids in the formation and the flow properties of the formation is indispensable to proper and efficient production of formation oil. For example, when a formation is first drilled it is necessary to know the original oil saturation to intelligently plan the future exploitation of the field. The quantity of oil present in the formation will often dictate the most efficient manner of conducting tertiary recovery operations, such as solvent flooding. The concentration of oil in the formation may indicate which of the several alternative tertiary recovery techniques might best be employed to produce the oil. In waterflooding operations, the relation between fractional flow and fluid saturations in the formation is required to provide an estimate of the oil recovery that might be obtained by flushing the formation with water.
There are several methods which are currently used to obtain the fluid saturations and flow properties of a formation. Coring, the most commonly used technique for acquiring this information, is a direct sampling of the formation rock and fluids. For example, a small segment of the formation rock saturated with fluid is cored from the formation and removed to the surface where its fluid content and permeability can be analyzed. This method, however, is susceptible to a fault common to any sampling technique; the sample taken may or may not be representative of the formation as a whole. Also, there is a genuine possibility that the coring process may change the fluid saturation or permeability of the extracted core. Moreover, coring can only be employed in newly drilled wells or open hole completions. In the vast majority of wells, casing is set through the oil-bearing formation when the well is initially completed. Core samples, therefore, cannot subsequently be obtained from such a well. Finally, coring by its very nature investigates only the properties of the formation rock and fluids in the immediate vicinity of the wellbore.
Another approach to obtaining reservoir fluid saturations and flow properties is by logging techniques. These techniques also investigate the formation rock and fluid properties for only a very short distance beyond the wellbore. These techniques study a rock-fluid system as an entity; it is often difficult by this approach to differentiate between the properties of the rock and its fluids.
Material balance calculations based on production history are another approach to the problem. Estimates of the fluid saturation acquired by this method are subject to even more variables than coring or logging. This technique requires a knowledge of the initial fluid saturation of the formation by some other method and knowledge of the source of recovered fluids.
More recent methods for determining fluid saturations in a subterranean formation are concerned with injection and production of trace chemicals into and out of the formation. In one method, a carrier fluid containing at least two tracers having different partition coefficients between the immobile fluid phase of the formation and the carrier fluid in which the tracers are contained is injected into one location in the formation and produced from another. Due to the different partition coefficients of the tracers, they will be chromatographically separated as they pass through the formation, and this chromatographic separation is a function of the saturation of the immobile phase. In another method a carrier fluid containing a reactive chemical substance is injected into the formation through a well. The carrier fluid-reactant solution is displaced into the formation and the well is shut-in to permit the reactant to undergo a chemical change to produce additional tracer materials having different partition coefficients. When the well is produced, the reactant tracers having differing partition coefficients are chromatographically separated, and the degree of separation is a function of the saturation of the immobile fluid phase. In still another method, a carrier fluid containing tracers is injected into the formation and permitted to move within the formation under the influence of fluid drift. There is a chromatographic separation of the tracers during the movement of the carrier fluid due to fluid drift. The carrier fluid is then produced, and the chromatographic separation is measured to determine fluid saturations of the immobile fluid phase.
While these more recent methods have applicability in determining fluid saturation in a subterranean formation, they are designed primarily for use in those formations containing essentially one mobile fluid phase. A principal problem with these methods is that the measured results can be extremely difficult to analyze if two mobile fluid phases are present.